Fractionation for full boiling range gasoline desulfurization

ABSTRACT

Savings in the processing of a naphtha boiling range feed containing a thiophene are achieved by fractionating the feed stream in a single dividing wall column to yield a C 6 -minus overhead stream, a side-draw containing the majority of the C 6  and C 7  paraffins and olefins, and a bottoms stream comprising C 7  and heavier hydrocarbons. A dividing wall column provides better control of the concentration of both thiophene and toluene in the side-draw. Less of the valuable naphtha is lost and the amount of thiophene in the overhead product is minimized.

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application is a Continuation of co-pending application Ser.No. 09/900,941 filed Jul. 9, 2001, the contents of which are herebyincorporated by reference in its entirety.

FIELD OF THE INVENTION

[0002] The invention is a process for the fractional distillation ofnaphtha or gasoline boiling range hydrocarbon fraction. Thisfractionation is performed upstream of processing units designed totreat an olefin containing overhead stream and a heavier hydrocarbonbottoms stream. The invention specifically relates to the use of adividing wall distillation column to separate a naphtha upstream ofdesulfurization units.

BACKGROUND OF THE INVENTION

[0003] The naphtha boiling range hydrocarbons sold commercially asgasoline are normally a blend of several streams produced in a petroleumrefinery. These include reformates and alkylates which are relativelysulfur free because of upstream refining. Another major source of thenaphtha boiling range hydrocarbons are processing units which do notreceive a highly desulfurized feed. These include hydrocracking units,coking units and fluidized catalytic cracking (FCC) process units. Thenaphtha boiling hydrocarbon product streams produced by these units willcontain sulfur in the form of several molecular forms includingmercaptans, sulfides, disulfides, thiophenes and benzothiophenes.

[0004] Some form of sulfur removal is normally applied to thesesulfur-containing hydrocarbon streams or to a blend of them to reducethe sulfur level of the final gasoline product. Increased environmentalconcerns are resulting in a worldwide lowering of the allowable level ofsulfur in gasoline, and it has become necessary to find ways to removeincreased amounts of sulfur from these hydrocarbon streams. This isespecially true in the case of the full boiling range naphtha recoveredfrom an FCC process, which often comprises a large fraction of theavailable gasoline pool and contains a significant amount of sulfur.

[0005] The removal of the sulfur is complicated by the various formsthat it takes and by the fact that hydrotreating, one of the predominantdesulfurization technologies, also hydrogenates olefins present in thesestreams. Paraffins tend to have lower octane numbers than thecorresponding olefin and hydrogenation therefore lowers the octanenumber of the naphtha fraction. As described below, various methods havebeen developed to remove sulfur compounds from naphtha boiling rangehydrocarbons. There remains however a further need for improvement indesulfurization technology which allows attaining very low sulfur levelswithout reducing the octane number of the fraction being treated.

RELATED ART

[0006] It has been recognized in the art that the sulfur containingcompounds in a cracked gasoline fraction tend to be concentrated in thehigher boiling, or heavier, portion of the gasoline. U.S. Pat. No.3,957,625 issued to B. A. Orkin discloses this and uses it to advantageby fractionating the cracked gasoline and then hydrotreating only theheavier fraction, thus avoiding hydrogenation of the lower boilingolefins. A similar approach is shown in FIG. 1 of a paper entitled“Novel Process for FCC Gasoline Desulfurization and Benzene Reduction toMeet Clean Fuels Requirements”, presented at the National Petrochemical& Refiners Association 2000 annual meeting March 26-28 in San Antonio,Tex.

[0007] A paper entitled “Removal of Sulfur From Light FCC Gasoline”,also presented at the National Petrochemical & Refiners Association 2000annual meeting March 26-28 in San Antonio, Tex. discloses that thesulfur compounds in the initial boiling point range of light FCCgasoline are predominantly mercaptans and that these mercaptans can beremoved by extraction into a caustic stream. The paper also points outthat as the boiling point of the gasoline increases, thiophenic sulfurstarts to appear in the gasoline. As thiophenes are not extractable bythe caustic it is desirable to set an endpoint to the fraction beingtreated by extraction which is low enough to exclude thiophenes. Thethiophenes therefore remain in the heavy fraction, which is hydrotreatedfor desulfurization.

[0008] U.S. Pat. No. 5,582,714 issued to P. Forte describes the problemof sulfur being present in FCC gasoline and recognizes thathydrotreatment of this stream will result in loss of octane bysaturation of olefinic hydrocarbons. The patent teaches the use ofliquid-liquid extraction of sulfur compounds into a solvent.

[0009] U.S. Pat. No. 6,228,254 also addresses the problem of sulfur ingasoline fraction but presents a two-step solution comprisinghydrotreating followed by adsorption or liquid extraction with anaqueous stream.

[0010] The dividing wall or Petlyuk configuration for fractionationcolumns was initially introduced some 50 years ago by Petlyuk et al.Dividing wall columns have been employed for the separation ofhydrocarbon mixtures as evidenced by the disclosure of U.S. Pat. No.2,471,134 issued to R. O. Wright. Recently, the use of dividing wallcolumns has begun to expand because of the greater recognition that incertain situations dividing wall columns can provide benefits abovethose of conventional fractionation columns. For instance, acommercialization of a fractionation column employing this technique isdescribed in the article appearing at page s14 of a supplement to TheChemical Engineer, Aug. 27, 1992.

[0011] U.S. Pat. No. 2,471,134 illustrates a dividing wall fractionationcolumn having a partition or dividing wall 20 dividing the trayed columninto two parallel vapor-liquid contacting chambers. A similar but moredetailed disclosure of a dividing wall fractionation column is providedby U.S. Pat. No. 4,230,533 issued to V. A. Giroux. Dividing wall columnsare closely related to a different type of column referred to as apartitioned distillation column such as illustrated in U.S. Pat. No.5,755,933 issued to Thomas P. Ognisty et. al. A partitioned distillationcolumn differs from a dividing wall column in that the vertical dividingwall is positioned such that it contacts one end of the column. Thus,only one terminal portion of the column is divided into the two parallelcontacting sections. In this manner two overhead products or two bottomproducts may be removed from a single column. A dividing wall columnproduces an intermediate boiling fraction.

SUMMARY OF THE INVENTION

[0012] It has been discovered that a significant improvement can beachieved in the overall performance of a complex which firstfractionates and then desulfurizes the resultant fractions of a fullboiling range gasoline by employing a dividing wall column to performthe fractionation. Such a column overcomes or at least reduces problemsresulting from the tendency of the thiophenes to form azeotropes withthe olefinic hydrocarbons.

BRIEF DESCRIPTION OF THE DRAWING

[0013] The drawing is a simplified process flow diagram showing thefractionation of a full boiling range FCC gasoline in a dividing wallcolumn into light, heavy, and intermediate boiling range fractions whichcan be separately treated for sulfur removal.

DETAILED DESCRIPTION AND PREFERRED EMBODIMENTS

[0014] The feed stream or streams to the subject process aresulfur-containing naphtha boiling range petroleum fractions such as FCCgasoline, coker naphtha, straight run gasoline and naphtha fractionsfrom conversion processes such as hydrocracking or thermal cracking.These gasoline blending component streams will normally have a boilingrange, as determined by the appropriate ASTM test method, fallingbetween about 38 and 260° C. (100-500° F.), which encompasses the rangeof boiling points for modern gasoline. The individual feeds may includea light naphtha having a boiling point range of from that of C₅ to about204° C. (400° F.), full range naphtha having a boiling point range fromabout that of C₅ hydrocarbons to about 249° C. (480° F.) and heavynaphtha boiling fraction distilling in the range of from about 126° C.(260° F.) to about 249° C. (480° F.).

[0015] These petroleum derived fractions will contain sulfur in the formof various compounds, with the relative amount of total sulfur, thetypes of molecule containing the sulfur and the distribution of sulfurbetween these molecular types being dependent upon a number of variablessuch as the crude oil source and the type of conversion unit(s) employedin its production. These factors are largely refinery specific and mayvary depending on the season, refinery operations in general and thesource of the crude oil being processed. The sulfur compounds in naphthaboiling range fractions are mainly mercaptans, aromatic heterocycliccompounds, sulfides and disulfides, but also include some thiophenes.Mercaptans in the feed stream will normally contain from 1 to 10 carbonatoms per molecule and are illustrated by methane thiol, 1-ethanethiol,2-propanethiol, 2-butanethiol, hexanethiol, octanethiol and thiophenol.Aromatic heterocyclic compounds which may be present includealkyl-substituted thiophenes. Specific examples of these compoundsinclude thiophene, 2-methylthiophene, 2-ethylthiophene, benzothiopheneand dimethylbenzothiophene.

[0016] The total sulfur content of the combined feed to the process willexceed about 100 wt ppm and will normally exceed 150 wt ppm. It mayrange up to 5000 wt ppm or more. As mentioned before, the sulfurcontaining compounds tend to be higher boiling and thus concentrated inthe higher boiling portion of these feed stream(s). Heavier feedfractions may contain over 9000 wt ppm sulfur. The feed streams oftencontain olefinic hydrocarbons. This again is refinery and feed specific.A feed stream recovered from an FCC unit is likely to have an olefincontent over 5 mol %, and often contains from about 10 to 40 percentolefins.

[0017] In order to meet the new gasoline sulfur content limitationsrefineries will need to remove a large amount of the sulfur present inthe sulfur-containing naphtha boiling range fractions blended into thegasoline. As mentioned above, hydrotreating of the entire fraction willnormally be undesired as it will result in the simultaneoushydrogenation of olefins to the lower octane number correspondingparaffin. An evolving strategy to deal with this problem is tofractionate the combined naphtha boiling range feedstocks into a lightand a heavy fraction, and to then process these streams differently. Thelight fraction is rich in the olefins and contains a low percentage ofthe total sulfur in the combined feedstocks. Most of the sulfur in thelight fraction is in the form of mercaptans, disulfides and dissolvedhydrogen sulfide and can be extracted by contacting with aqueous causticsolutions with little or no loss of octane.

[0018] The heavy fraction formed by fractionation of the combinedfeedstocks will contain a lower amount of olefins and will contain amajority of the sulfur present in the combined feedstocks. Much of thissulfur is in the form of thiophene, benzothiophene and substitutedderivatives of these two compounds. Thiophene is the lowest boiling ofthese compounds and therefore the most likely to be present in thelighter fraction. Thiophene is not effectively removed from the lighthydrocarbon fraction by caustic extraction. The dividing point betweenthe light and heavy fractions is therefore set to allow only as muchthiophene to enter the light fraction as will allow the treated lightfraction to meet the sulfur limitation as a gasoline blending component.The rest of the thiophene must be rejected into the heavy fraction,which is passed into a hydrogenative treatment as needed to affectdesulfurization. At the same time it is desired to maximize the size ofthe light fraction to in turn maximize the amount of olefins which areretained. This defines the operational constraints of the fractionationcolumn which performs the separation of the combined feedstock into thelight and heavy fraction.

[0019] An additional cost factor which must be considered is that thesaturation of olefins consumes hydrogen, which is a valuable commodityin a refinery. It is therefore also desired to avoid saturation of theolefins to minimize the operating cost of the hydrotreating step.

[0020] There are several problems intrinsic to controlling the split ofthe feedstock between the heavy and light fractions performed in thefractionation column while attempting to maximize the content of olefinsin the light fraction. First, the amount of thiophene present in thefeedstock is usually unknown at any specific time and tends to varydepending on operating conditions in upstream units such as the FCC andchanges in feeds to the FCC or other units which produce the feedstock.This is further complicated by the fact that measurement of thethiophene content in FCC naphtha is difficult. In the standard analysisby gas chromatography, thiophene is aliased with sec-butyl mercaptan, acompound which is easily removed by caustic scrubbing. A thirdcomplicating problem is that thiophene exhibits a strongly non-idealvapor liquid equilibrium in mixtures of other compounds present in FCCnaphtha. Azeotropes are known to form between thiophene and manycompounds present in gasoline. For example, azeotropes have beenreported between thiophene and n-hexane, n-heptane, and benzene. Fromthis it can be inferred that thiophene will also form azeotropes withhomologous compounds of these species. Operational data has alsoindicated that thiophene will accumulate in lighter boiling fractionsthan would be expected based upon its normal boiling point of 84° C.(183° F.).

[0021] Because of these problems, a conservative approach is to designand control the fractionation column to operate with only a low recoveryof the olefins overhead in the light fraction. This results in asubstantial amount of C₆ olefins being left in the heavy fractionresulting in both octane loss and unnecessary hydrogen consumption whenthe olefins are hydrogenated.

[0022] It is an objective of the subject invention to improve thefractionation of the naphtha boiling range feedstock to reduce unneededolefin saturation. It is a further objective to in general improve thefractional distillation performed in reducing the sulfur content of thisfeedstock. These objectives are met in part by withdrawing anintermediate stream from a mid-point of the naphtha splitter column.This intermediate stream should contain most of the thiophene whichenters the splitter column and also the co-boiling C₆ and C₇ olefins. Inthe subject invention the intermediate stream is formed through use of adividing wall column. While dividing wall columns often provide reducedcapital and utilities costs, the main advantage provided by the use of adividing wall column is that the composition of the intermediatefraction can be controlled more precisely. This tighter specification onthe boiling range of the intermediate stream allows a reduction in theflow rate of the intermediate stream and improved operational control.This tighter control on the composition of the intermediate stream alsohas advantages in the downstream treating of the intermediate stream.For instance it allows a reduction in the amount of toluene which ispresent in the intermediate stream. This is an advantage when theintermediate stream is treated by solvent extraction to remove thesulfur compounds. The solvent e.g. a sulfolane solution, will alsoextract aromatic hydrocarbons therefore removing them from theintermediate stream. This reduces the amount of recovered intermediateblending stock and increases the flow rates in the recovery sections ofthe extraction zone resulting in increased operational costs. It istherefore advantageous to minimize the toluene concentration in theintermediate stream. Similarly, if an extractive separation is performedto remove the sulfur compounds, it is important to minimize the amountof methyl thiophene that is removed in the intermediate steam. Thepartition coefficient of methyl thiophene in sulfolane is approximatelyhalf of that of thiophene. Thus, any methyl thiophene that is removed inthe intermediate stream will also result in a need for a larger capacityextraction system. A properly designed and operated dividing wall columnwill allow for a sharper separation between the C₇ normal olefin andmethyl thiophene, allowing for a greater C₇ normal olefin recovery inthe intermediate stream while still minimizing the loss of methylthiophene in this stream. The use of a dividing column allows a sharperseparation to be achieved than is possible in a side-draw column, whilereducing capital cost, plot space requirements, and energy cost comparedto a sequence of two distillation columns.

[0023] The process of the invention is illustrated in the Drawing, whichis intended only to describe one embodiment of the invention and is notintended to limit either its application or scope. Referring now to thedrawing, a combined feedstock stream is passed through process line 1into a dividing wall column 2. The depiction of the column is simplifiedas all the auxiliary operational components, such as controls, trays,condenser, and reboiler, may be of conventional design. Different feedstreams can be fed into the column at different locations ifappropriate. This column is the splitter column which produces thelight, intermediate, and heavy fractions of the feedstock. The dividingwall column 2 is distinguished by the presence of a vertical dividingwall 3 in a vertical mid portion of the column, also referred to as thedividing wall portion of the column. This dividing wall 3 extendsbetween opposing sides of the inner surface of the column and joins itin a substantially fluid tight seal. Thus fluids cannot passhorizontally from one side of the column to the other and must insteadtravel either over or under the wall. The dividing wall 3 divides thecentral portion of the column into two parallel fractionation zones orchambers, which may be of different cross-section. Each chamber, and therest of the column, will contain conventional vapor liquid contactingequipment such as trays or packing. The type of tray and design detailssuch as tray type, tray spacing and layout may vary within the column 2and between the two parallel chambers of the dividing wall portion ofthe column.

[0024] The dividing wall column 2 separates all of the entering naphthaboiling range hydrocarbons into an overhead stream containing all of thecompounds having boiling points less than the C₆ olefins, anintermediate side cut stream containing C₆ and C₇ olefins and a majorityof the thiophene, and a bottoms stream containing the heavier C₇-pluscompounds. As with any fractional distillation there will be someoverlap and tailing of compositions between the three cuts.

[0025] The light fraction is removed as an overhead stream comprisinglight hydrocarbons such as butane, pentane, any hydrogen sulfidedissolved in a feed stream, co-boiling mercaptans and some C₆hydrocarbons via line 4 and passed into a treating zone 7. This zone maybe of conventional design such as an extraction with an aqueous alkalinesolution which will remove hydrogen sulfide and mercaptans and willproduce a low sulfur light product stream of line 8.

[0026] The intermediate stream of line 6 will comprise C₆ and C₇ normaland branched olefins and thiophene. It is preferably passed via line 6into a treating zone 11 in which it is preferably contacted with asolvent under conditions which effect the selective removal of thiopheneand other sulfur compounds present. This separation forms a sulfurcontaining extract stream removed via line 13 and a treated intermediateproduct stream carried by line 12. A solvent extraction or extractivedistillation zone of this type can utilize a solvent such as sulfolaneor a sulfolane derivative, dimethyl sulfoxide, or tetraethylene glycol.It is operated at conventional extraction promoting conditions. Thepaper cited above entitled “Novel Process for FCC GasolineDesulfurization and Benzene Reduction to Meet Clean Fuels Requirements”,discusses this form of treating and may be consulted for furtherinformation. It however addresses the simultaneous removal of aromatics.Further information on extraction of sulfur compounds can be obtained byreference to previously cited U.S. Pat. No. 5,582,714, which isincorporated herein for its teaching on this subject. This patentdiscloses that sulfur can be removed from FCC gasoline by solventextraction using polyalkylene glycol or polyalkylene glycol ether ormixtures thereof, with the resultant sulfur-containing extract streamthen being subjected to hydrogenation. U.S. Pat. No. 2,634,230 describesthe use of 2,4 dimethyl sulfolane to extract sulfur compounds fromhighly olefinic naphthas. It is also possible to treat the intermediatestreams by means other than extraction. For instance, the treating zone11 may contain catalytic treatment steps. The intermediate stream may bepassed into a selective hydrogenation zone in which thiophene ishydrogenated in the presence of olefins. A different means of treatingthe intermediate stream is to pass it into a hydrotreating zone, whichcan be used to prepare the feed to a catalytic naphtha reforming unit.While this results in olefin loss, it may be a low cost processingoption if the refinery already contains hydrotreating and reformingunits with available capacity.

[0027] The heavy fraction produced in column 2 comprises C₇ and heavierhydrocarbons and co-boiling sulfur containing compounds originallypresent in the feed stream. This stream is withdrawn via line 5 and istreated in zone 9 by conventional hydrodesulfurization or possibly acombination of conventional steps to remove the sulfur containingcompounds. As the heavy fraction has a low concentration of olefins,hydrogenation does not significantly degrade the octane of this streamas it would the other two fractions. The product effluent of thetreatment zone 9 is removed via line 10. It is then combined with thetreated light and intermediate streams to form a treated full boilingrange product stream.

[0028] The following is presented as a non-limiting illustrativeexample. It is a comparison of the projected performance of a regularcolumn producing an intermediate stream by means of a side draw off thecolumn and that of a dividing wall column. The comparison is based uponhaving the same number of separatory stages and same reboiler duty inboth columns. There was no attempt to optimize operation or design ofthe dividing wall column. The comparison design specification is1.32×10⁻⁵ lb thiophene/lb overhead product, the recovery of at least 95percent of the C₇ normal olefin and less than 20 percent of the toluenein the intermediate fraction. The reflux ratio needed to meet thisspecification for the simple splitter case was fixed for the dividingwall column case. The feed rate is 10,000 lb/hr.

[0029] Both the simple splitter side draw column and the dividing wallcolumn contain 30 stages of separation. The reboiler duty is 2.1 MMBTU/hr, and for each case the recovery of normal C₇ olefin in theintermediate stream equals 95 percent of the C₇ olefin in the feed. Thesimple side draw column produces an intermediate steam having a flowrate of 2885 lb/hr, with a toluene recovery in the intermediate streamof 0.20, (which indicates 20 wt-% of the toluene in the feed stream is“recovered” in the intermediate stream) a methyl thiophene recovery of0.22, and a C₅ olefin recovery of 0.07. Compare this to a case using adividing wall column. The intermediate stream has a flow rate of 2748lb/hr, a toluene recovery of 0.17, a methylthiophene recovery of 0.208,and a C₅ olefin recovery of 0.06. This indicates that the dividing wallcolumn has achieved a better separation than the simple sidedraw column.This is beneficial when the intermediate fraction is sent, for example,to a solvent extraction unit. For instance, for a typical set ofgasoline sulfur specifications, the required solvent flow for thesidedraw case is 6687 lb/hr versus 6307 lb/hr for the dividing wallcolumn. The reduction in solvent flow for the dividing wall column casewill have a beneficial impact on the cost of the solvent system. The useof a dividing wall column therefore provides important economic benefitsfor both the fractionation and in downstream treating steps. It allows asharper separation to be achieved than is possible in a side-drawcolumn, while simultaneously reducing capital cost, plot spacerequirements, and energy cost compared to a sequence of two columns.

What is claimed is:
 1. In a process for the treatment of a naphtha boiling range hydrocarbon to remove sulfur containing compounds wherein the naphtha boiling range hydrocarbon is separated by fractional distillation yielding at least light and heavy fractions, the improvement which comprises performing the fractional distillation in a dividing wall column and producing an intermediate fraction comprising C₇ olefins and thiophene.
 2. A process for the desulfurization of a naphtha boiling range feedstock comprising sulfur compounds, which process comprises: passing the feedstock into a dividing wall column and separating the feedstock into a light fraction comprising mercaptans, olefinic hydrocarbons and paraffinic hydrocarbons having less than six carbon atoms per molecule, an intermediate fraction comprising C₆ and C₇ olefinic hydrocarbons and thiophene, and a heavy fraction comprising sulfur compounds and hydrocarbons containing more than seven carbon atoms per molecule; treating the intermediate fraction in an intermediate treating zone, in which thiophenes are removed, to form a treated intermediate stream; and treating the heavy fraction in a heavy treating zone, in which sulfur containing compounds are subjected to hydrotreating, to form a treated heavy stream.
 3. The process of claim 2 further comprising passing the light fraction into a light treating zone, in which mercaptans are removed to form a treated light stream.
 4. The process of claim 3 wherein the light fraction is contacted with an aqueous alkaline solution in the light treating zone to extract the light sulfur compounds.
 5. The process of claim 2 further characterized in that the concentration of thiophene in the light fraction is controlled to be less than 50 wt ppm.
 6. The process of claim 2 further characterized in that the recovery of C₇ olefinic hydrocarbons in the intermediate stream is greater than 30% of the C₇ olefinic hydrocarbon content of the feedstock.
 7. The process of claim 2 further characterized in that the intermediate treating zone comprises a solvent extraction zone in which thiophene is removed from the intermediate fraction.
 8. The process of claim 7 in which the solvent comprises sulfolane or a sulfolane derivative.
 9. The process of claim 7 in which the solvent comprises dimethyl sulfoxide.
 10. The process of claim 7 in which the solvent comprises tetraethylene glycol.
 11. The process of claim 2 further characterized in that the intermediate treating zone comprises a selective hydrogenation zone in which thiophene is hydrogenated in the presence of olefins.
 12. The process of claim 2 further comprising passing the treated intermediate stream into a catalytic naphtha reforming zone. 